UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT PURSUANT TO
SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Date of report (Date of earliest event reported): September 7, 2022
(Exact name of registrant as specified in charter)
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| (Address of principal executive offices) | (Zip code) | |||||||
Registrant’s telephone number, including area code: (918 ) 513-4570
Not Applicable
(Former name or former address, if changed since last report)
Securities registered pursuant to Section 12(b) of the Exchange Act:
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Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
| Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425) | |||||||||||
| Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12) | |||||||||||
| Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b)) | |||||||||||
| Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c)) | |||||||||||
Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter). | |||||||||||
Emerging Growth Company | |||||||||||
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ | |||||||||||
Item 7.01. Regulation FD Disclosure.
On September 7, 2022, Laredo Petroleum, Inc. (the "Company") posted to its website an investor presentation (the "Presentation"). The Presentation is available on the Company's website, www.laredopetro.com, and is attached hereto as Exhibit 99.1 and incorporated into this Item 7.01 by reference.
All statements in the Presentation, other than historical financial information, may be deemed to be forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Although the Company believes the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements are not guarantees of future performance, and actual results or developments may differ materially from those in the forward-looking statements. See the Company's Annual Report on Form 10-K for the year ended December 31, 2021 and the Company's other filings with the SEC for a discussion of other risks and uncertainties. The Company disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.
In accordance with General Instruction B.2 of Form 8-K, the information furnished under this Item 7.01 of this Current Report on Form 8-K and the exhibits attached hereto are deemed to be "furnished" and shall not be deemed "filed" for the purpose of Section 18 of the Exchange Act, or otherwise subject to the liabilities of that section, nor shall such information be deemed incorporated by reference into any filing under the Securities Act or the Exchange Act.
Item 9.01. Financial Statements and Exhibits.
(d) Exhibits.
| Exhibit Number | Description | |||||||
| 104 | Cover Page Interactive Data File (formatted as Inline XBRL). | |||||||
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
| LAREDO PETROLEUM, INC. | ||||||||
Date: September 7, 2022 | By: | /s/ Bryan J. Lemmerman | ||||||
| Bryan J. Lemmerman | ||||||||
| Senior Vice President and Chief Financial Officer | ||||||||
September 2022 Investor Presentation EXHIBIT 99.1
This presentation, including any oral statements made regarding the contents of this presentation, contains forward-looking statements as defined under Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, that address activities that Laredo Petroleum, Inc. (together with its subsidiaries, the “Company”, “Laredo” or “LPI”) assumes, plans, expects, believes, intends, projects, indicates, enables, transforms, estimates or anticipates (and other similar expressions) will, should or may occur in the future are forward-looking statements. The forward- looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. Such statements are not guarantees of future performance and involve risks, assumptions and uncertainties. General risks relating to Laredo include, but are not limited to, the decline in prices of oil, natural gas liquids and natural gas and the related impact to financial statements as a result of asset impairments and revisions to reserve estimates, the ability of the Company to execute its strategies, including its ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to its financial results and to successfully integrate acquired businesses, assets and properties, oil production quotas or other actions that might be imposed by the Organization of Petroleum Exporting Countries and other producing countries (“OPEC+”), the outbreak of disease, such as the coronavirus (“COVID-19”) pandemic, and any related government policies and actions, changes in domestic and global production, supply and demand for commodities, including as a result of the COVID-19 pandemic, actions by OPEC+ and the Russian-Ukrainian military conflict, long-term performance of wells, drilling and operating risks, the increase in service and supply costs, including as a result of inflationary pressures, tariffs on steel, pipeline transportation and storage constraints in the Permian Basin, the possibility of production curtailment, hedging activities, the impacts of severe weather, including the freezing of wells and pipelines in the Permian Basin due to cold weather, possible impacts of litigation and regulations, the impact of the Company’s transactions, if any, with its securities from time to time, the impact of new laws and regulations, including those regarding the use of hydraulic fracturing, the impact of new environmental, health and safety requirements applicable to the Company’s business activities, the possibility of the elimination of federal income tax deductions for oil and gas exploration and development and other factors, including those and other risks described in its Annual Report on Form 10-K for the year ended December 31, 2021, and those set forth from time to time in other filings with the Securities and Exchange Commission (“SEC”). These documents are available through Laredo’s website at www.laredopetro.com under the tab “Investor Relations” or through the SEC’s Electronic Data Gathering and Analysis Retrieval System at www.sec.gov. Any of these factors could cause Laredo’s actual results and plans to differ materially from those in the forward-looking statements. Therefore, Laredo can give no assurance that its future results will be as estimated. Any forward-looking statement speaks only as of the date on which such statement is made. Laredo does not intend to, and disclaims any obligation to, correct, update or revise any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. The SEC generally permits oil and natural gas companies, in filings made with the SEC, to disclose proved reserves, which are reserve estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, and certain probable and possible reserves that meet the SEC’s definitions for such terms. In this presentation, the Company may use the terms “resource potential,” “resource play,” “estimated ultimate recovery,” or “EURs,” “type curve” and “standard ized measure,” each of which the SEC guidelines restrict from being included in filings with the SEC without strict compliance with SEC definitions. These terms refer to the Company’s internal estimates of unbooked hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques. “Resource potential” is used by the Company to refer to the estimated quantities of hydrocarbons that may be added to proved reserves, largely from a specified resource play potentially supporting numerous drilling locations. A “resource play” is a term used by the Company to describe an accumulation of hydrocarbons known to exist over a large areal expanse and/or thick vertical section potentially supporting numerous drilling locations, which, when compared to a conventional play, typically has a lower geological and/or commercial development risk. “EURs” are based on the Company’s previous operating experience in a given area and publicly available information relating to the operations of producers who are conducting operations in these areas. Unbooked resource potential and “EURs” do not constitute reserves within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or SEC rules and do not include any proved reserves. Actual quantities of reserves that may be ultimately recovered from the Company’s interests may differ substantially from those presented herein. Factors affecting ultimate recovery include the scope of the Company’s ongoing drilling program, which will be directly affected by the availability of capital, decreases in oil, natural gas liquids and natural gas prices, well spacing, drilling and production costs, availability and cost of drilling services and equipment, lease expirations, transportation constraints, regulatory approvals, negative revisions to reserve estimates and other factors, as well as actual drilling results, including geological and mechanical factors affecting recovery rates. “EURs” from reserves may change significantly as development of the Company’s core assets provides additional data. In addition, the Company’s production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases. “Type curve” refers to a production profile of a well, or a particular category of wells, for a specific play and/or area. The “standardized measure” of discounted future new cash flows is calculated in accordance with SEC regulations and a discount rate of 10%. Actual results may vary considerably and should not be considered to represent the fair market value of the Company’s proved reserves. This presentation includes financial measures that are not in accordance with generally accepted accounting principles (“GAAP”), such as Consolidated EBITDAX and Free Cash Flow. While management believes that such measures are useful for investors, they should not be used as a replacement for financial measures that are in accordance with GAAP. For definitions of such non-GAAP financial measures, please see the Appendix. Unless otherwise specified, references to “average sales price” refer to average sales price excluding the effects of the Company’s derivative transactions. All amounts, dollars and percentages presented in this presentation are rounded and therefore approximate. 2 Forward-Looking / Cautionary Statements
35% 47% 28.4 38.5 FY-19A FY-22E ($624) ($644) ($482) ($351) ($454) ~($550) ~($585) ($246) ($106) $60 $12 ($3) ~$280 ~$560 FY-17A FY-18A FY-19A FY-20A FY-21A FY-22E FY-23E Multi-Year Strategic Transformation Yields a “New” Laredo 3 ▪ Low-cost, efficient and safe operations ▪ Optimizing production through digital and innovative solutions ▪ Reducing emissions and flaring ▪ Local philanthropy and community engagement ▪ Committed to diversity and inclusion ▪ Added ~57,000 oil-weighted net acres in the Midland Basin ▪ ~8 years of inventory primarily across Howard County and western Glasscock County ▪ Strong proved reserve base ▪ Broad portfolio of digital solutions ▪ Hired key leadership roles including CEO, CFO, Chief Sustainability Officer and Chief Technology Officer ▪ Refreshed 80% of Board over the past three years ▪ Board is 60% diverse based on race/gender ▪ Separated Chairman and CEO roles ▪ Maximize Free Cash Flow1 ▪ Optimize capital structure through debt and leverage reductions ▪ Return of capital to shareholders ▪ Advance sustainability New Leadership New Strategy New Assets New Capabilities Expanded Inventory ✓ Shifted Commodity Mix ✓ Reduced Leverage ✓ Balanced Investment & Capital Discipline ✓ Generating Free Cash Flow1✓ Outspending Cash Flow Capital Discipline & Portfolio Repositioning FCF Generation2 ~$200MM Stock Repurchase Target ~$700MM Debt Reduction Target 2022-2023 Capital Expenditures $MM Free Cash Flow $MM 1See Appendix for definitions of non-GAAP financial measures; 2Assumes 2022 WTI oil price / HH gas price of $100 / $7.00 (1H-22 actualized) and 2023 WTI oil price / HH gas price of $90 / $5.65 Oil Production MBo/d & Oil % Portfolio Repositioning 2019 - 2021 Return of Capital 2022+ Net Acres Oil-Weighted ~66,000 Eastern ~100,000
$1.48 Equity $1.48 Equity $1.48 Equity $0.61 Equity Uplift $0.61 Equity Uplift $0.73 Equity Uplift $1.13 Net Debt $0.52 Net Debt $0.52 Net Debt$2.6 $2.6 $3.3 Current $700 MM Debt Reduction 3.5x EV / '22E EBITDA 0.0x 1.0x 2.0x 3.0x 4.0x 5.0x 6.0x LPI Reducing Debt and Leverage ▪ Absolute net debt target of $700 to $750 million ▪ Achieving leverage target of <1.0x in 2Q-23 ✓ Repurchasing Shares Opportunistically ▪ Two-year program authorized through May 27, 2024 ▪ $200 million stock repurchase target ✓ 1See Appendix for definitions of non-GAAP financial measures; 2Assumes 2022 WTI oil price / HH gas price of $100 / $7.00 (1H-22 actualized) and 2023 WTI oil price / HH gas price of $90 / $5.65 3Less than or equal to $55 breakeven oil price; 4Source JP Morgan Research as of 7/28/2022 5Peer Group (PXD, CTRA, DVN, EOG, HES, CPE, SM, MRO, RRC, CLR, FANG, MTDR, AR, CNX, EQT, PDCE, APA, CHK, MUR, SWN, OVV) “New” Laredo Focused on Driving Shareholder Value Enterprise Value / 2022E EBITDA - Peer Comparison4,5 4 Equitizing Enterprise Value - $B Avg. Multiple 3.5x Maintaining Capital Discipline ▪ Strong asset performance supports steady reinvestment rate ▪ Ability to maintain current oil production at ~60% reinvestment rate ✓ Generating Free Cash Flow1 ▪ Two-year projected total of ~$840 million (2022-23)2 ▪ Sustainable Free Cash Flow supported by eight years of oil-weighted inventory3 ✓ Expanding Value ▪ Trading at a discount to Proved Developed Reserves value ▪ Highest 2022-23 Free Cash Flow yield in peer group5 ✓ Peer Group Debt Reduction Multiple Expansion Illustrative Value
2.14x 1.93x 1.39x 4Q-21A 1Q-22A 2Q-22A $9 $7 4Q-21A 1Q-22A 2Q-22A 3Q-22A (QTD) $32 $59 4Q-21A 1Q-22A 2Q-22A 3Q-22A (QTD) ✓ Deleveraging 1Incurred capital expenditures; 2See Appendix for definitions of non-GAAP financial measures; 33Q-22A QTD as of August 2, 2022 Executing the Plan 5 ✓ Oil Production ✓ Capital Discipline1 ✓ Free Cash Flow2 ✓ Repurchasing Debt3 ✓ Repurchasing Shares3 41.1 40.3 40.6 4Q-21A 1Q-22A 2Q-22A $142 $171 $138 4Q-21A 1Q-22A 2Q-22A $25 $23 $110 4Q-21A 1Q-22A 2Q-22A (Units in MBo/d) (Units in $ millions) (Units in $ millions) (Net Debt to Consolidated EBITDAX2 Multiple) (Units in $ millions) (Units in $ millions) Program Initiated 2Q-22 Program Initiated 2Q-22
0 25 50 75 100 125 150 175 200 0 90 180 270 360 C u m u la ti v e G ro s s O il P ro d u c ti o n p e r W e ll ( M B O ) Producing Days 1Timing based on estimated flowback date; 2Production data normalized to 10,000’ lateral length, downtime days Development Program in 2H-22 & FY-23 Primarily Focused on North Howard Howard Strong Performance in North Howard Driving 2H-22 and FY-23 Expectations 6 North Howard Development ▪ 100% of 2H-22 and 92% of FY-23 TIL’s ▪ Oil production outperforming Central Howard by ~25% ▪ Expected to generate ~60% of FY-23 oil production ▪ Middle Sprayberry continuing to outperform expectations with nine wells set to turn-in-line during 2023 Central Howard Development ▪ ~80% of Central Howard developed; 23 remaining locations in three DSUs ▪ Scheduled TIL’s: Five in FY-23 and 18 in FY-24 North Howard Central Howard Average Well Performance2 LPI Producing 2H ‘2022 TIL 2023 TIL 2024 TIL LPI OBO Net Acres North Howard Middle Spraberry (North Howard) Central Howard (2Q-21+) Central Howard (4Q-20 to 1Q-21) Leech (2Q-22) Leech DSU
100 125 130 165 165 60 195 275 295 295 ≤$40 ≤$45 ≤$50 ≤$55 Inventory Upside Near-term Development Focus 1Gross operated location as of January 2022 (adjusted for 2021 completions) 2Locations may require the formation of drilling units to develop 3Flat oil price needed to achieve 10% IRR assuming gas price at 20:1 ratio Development Focus Areas ~460 ~320 ~1502 Avg. Breakeven Oil Price3 ~8 Years of Inventory1 Assumes: ▪ Current activity pace ▪ Low-risk, operated only ▪ Current development spacing ▪ <$55 breakeven oil price Howard Glasscock Howard W. Glasscock Eastern Reagan Midland Martin Sterling Mitchell ~160 Low Breakeven Oil Inventory Underpins Sustainable Free Cash Flow Generation 7 ~405 Howard W. Glasscock Eastern
1,117' 1,314' 1,439' 1,577' FY-19A FY-20A FY-21A YTD-22A 10,750' 9,950' 10,000' 12,653' FY-19A FY-20A FY-21A YTD-22A 1,274' 1,408' 1,653' 1,584' FY-19A FY-20A FY-21A YTD-22A ~4 Yrs. Current Sand Inventory2 Drilling Ft. Per Day Per Rig Disciplined, Efficient Capital Program Maintains Prior Year Activity Levels 2022E Capital Program FY-22 Guidance Capital Expenditures ($MM) ~$550 Avg. Rig Count (Op) ~2.3 Avg. Frac Crews (Op) ~1.2 Spuds 65 Gross (62.9 Net) Completions 55 Gross (53.1 Net) Turn-in-Lines 55 Gross (53.1 Net) Production (MBOE/d) 82.0 – 83.5 Oil Production (MBO/d) 38.0 – 39.0 81% 8% 7% 4% Capital Expenditures by Category DC&E (op) Facilities & Land Corporate DC&E (non-op) 8 Continuous Improvement Drives Capital Efficient Drilling and Completion Program Company Owned Sand Mine Reduces Well Costs and Protects Against Inflation Avg. Completed Lateral Length 1Based on Howard County 10,000’ lateral length completions; 2Based on current pace of development Fractured Ft. Per Day Per Crew ▪ Located on Laredo owned surface acreage ▪ Operated by a third party ▪ Reduces emissions by: − Elimination of truck traffic − Utilization of wet sand >$400K Per Well Savings1
$567 $332 $348 $1,000 2022 2023 2024 2025 2026 2028 2029 2.61x 2.14x 1.93x 1.39x <1.35x <1.25x <1.15 <1.00 FY-20A FY-21A 1Q-22A 2Q-22A 3Q-22E 4Q-22E 1Q-23E 2Q-23E ~$245 ~$260 ~$280 ~$310 ~$420 ~$560 ~$685 ~$810 $80 $90 $100 $110 $80 $90 $100 $110 1See Appendix for definitions of non-GAAP financial measures; 2Assumes 2022 WTI oil price / HH gas price of $100 / $7.00 (1H-22 actualized) and 2023 WTI oil price / HH gas price of $90 / $5.65; 3As of 8/2/2022 41H-22 pricing actualized Free Cash Flow Driving Return of Capital and Debt Reductions 9 Rapidly Deleveraging through Free Cash Flow1 Generation Current Debt Maturity Profile3Free Cash Flow1 Sensitivities - $MM Net Debt to Consolidated EBITDAX1,2 Borrowing Base $1,250 MM Elected Commitment $1,000 MM Cash Balance $114 MM Liquidity ~$1,114 MM 9.500% Sr. Notes 2025 10.125% Sr. Notes 2028 7.750% Sr. Notes 2029 Drawn Credit Facility Undrawn Credit Facility 2022-23 Debt Reduction Target ~$700 million Current Liquidity3 ~$1.1 billion Two-Year Stock Repurchase Program through May 27, 2024 ~$200 million 2Q-23E Net Debt to Consolidated EBITDAX1,2 <1.0x Target Benchmark WTI Oil Price (per BBL) (Benchmark HH Gas Price assumes $7.00/mcf) Benchmark WTI Oil Price (per BBL) (Benchmark HH Gas Price assumes $5.65/mcf) 2022E Free Cash Flow1,4 (~$550 million capex) 2023E Free Cash Flow1 (~$585 million capex)
$2,798 $2,463 $2,922 $3,380 $3,840 SEC Pricing $55 $65 $75 $85 2.8x 2.3x 2.1x 2.0x 2.0x 1.9x 1.9x 1.8x 1.8x 1.7x 1.6x Average 1.6x 1.6x 1.5x 1.3x 1.2x 1.2x 1.2x 1.1x 1.1x 1.1x 1.1x 1.0x LPI 10 Significant Upside Potential Supported by Strong Reserves and Cash Flow 1See Appendix for definitions of non-GAAP financial measures; 2SEC pricing $63 benchmark oil and $3.35 benchmark gas / YE-21 reserves; 3Source Capital One Research as of 7/27/2022 4Source JP Morgan Research as of 7/28/2022; 5Peer Group (PXD, CTRA, DVN, EOG, HES, CPE, SM, MRO, RRC, CLR, FANG, MTDR, AR, CNX, EQT, PDCE, APA, CHK, MUR, SWN, OVV) PV-101,2 Proven Developed Producing Reserve Value Sensitivity - $MM Current Adj. Enterprise Value / PDP – Peer Comparison3,5 P e e r G ro u p EV / EBITDA vs. 2-Year FCF Yield – Peer Comparison4,5 0.0x 2.0x 4.0x 6.0x 8.0x 0% 20% 40% 60% 80% LPI Average
Generating Significant Free Cash Flow1 Returning Capital to Shareholders Reducing Debt and Improving Leverage Equity Upside Potential vs. Peer Group2 1See Appendix for definitions of non-GAAP financial measures 2Peer Group (PXD, CTRA, DVN, EOG, HES, CPE, SM, MRO, RRC, CLR, FANG, MTDR, AR, CNX, EQT, PDCE, APA, CHK, MUR, SWN, OVV) Compelling Investment Opportunity 11
Appendix
2H-22 & FY-22 GUIDANCE Guidance Commodity Prices Used for 3Q-22 Jul-22 Aug-22 Sep-22 3Q-22 Avg. Crude Oil: - - - - WTI NYMEX ($/BBO) $99.39 $98.05 $96.20 $97.90 Brent ICE ($/BBO) $104.84 $103.86 $101.36 $103.38 Natural Gas: - - - - Henry Hub ($/MMBTU) $6.55 $8.69 $8.23 $7.82 Waha ($/MMBTU) $5.62 $7.92 $7.34 $6.96 Natural Gas Liquids: - - - - C2 ($/BBL) $24.15 $24.99 $24.57 $24.57 C3 ($/BBL) $48.09 $48.56 $48.35 $48.34 IC4 ($/BBL) $64.43 $57.80 $57.44 $59.92 NC4 ($/BBL) $53.89 $54.39 $54.50 $54.25 C5+ ($/BBL) $79.10 $77.81 $77.86 $78.26 Composite ($/BBL)1 $42.57 $42.80 $42.56 $42.64 3Q-22 4Q-22 FY-22 Production: - - Total Production (MBOE/D) 78.5 – 81.5 77.5 – 80.5 82.0 – 83.5 Crude Oil Production (MBO/d) 35.5 – 37.5 35.5 – 37.5 38.0 – 39.0 Incurred Capital Expenditures ($MM): ~$120 ~$120 ~$550 Average Sales Price Realizations (excluding derivatives): - - - Crude Oil (% of WTI) 103% - - Natural Gas Liquids (% of WTI) 31% - - Natural Gas (% of Henry Hub) 72% - - Net Settlements Received (Paid) for Matured Commodity Derivatives ($MM): - - - Crude Oil ($MM) ($100) - - Natural Gas Liquids ($MM) ($12) - - Natural Gas ($MM) ($30) - - Operating Costs & Expenses ($/BOE): - - - Lease Operating Expenses $5.70 - - Production & Ad Valorem Taxes (% of Oil, NGL & Natural Gas Revenues) 7.0% - - Transportation and Marketing Expenses $1.75 - - General and Administrative Expenses (excluding LTIP) $1.80 - - General and Administrative Expenses (LTIP Cash) $0.40 - - General and Administrative Expenses (LTIP Non-Cash) $0.30 - - Depletion, Depreciation and Amortization $10.25 - - Note: Supports average sales price realization and derivatives guidance 13 1Current NGL composition C2 (42%), C3 (33%), IC4 (3%), NC4 (11%) and C5+ (11%)
(Volume in MBO; Price in $/BBO) Q3-22 Q4-22 2H-22 Q1-23 Q2-23 Q3-23 Q4-23 FY-23 Brent Swaps 1,040 1,040 2,079 - - - - - WTD Price $48.34 $48.34 $48.34 - - - - - Brent Collars 391 391 782 - - - - - WTD Floor Price $56.65 $56.65 $56.65 - - - - - WTD Ceiling Price $65.44 $65.44 $65.44 - - - - - WTI Swaps 92 92 184 - - - - - WTD Price $64.40 $64.40 $64.40 - - - - - WTI Collars 1,408 1,408 2,815 1,620 1,638 552 552 4,362 WTD Floor Price $72.65 $72.65 $72.65 $67.22 $67.22 $70.00 $70.00 $67.93 WTD Ceiling Price $86.54 $86.54 $86.54 $81.50 $81.50 $87.02 $87.02 $82.89 Total Swaps/Collars 2,930 2,930 5,860 1,620 1,638 552 552 4,362 WTD Floor Price $61.63 $61.63 $61.63 $67.22 $67.22 $70.00 $70.00 $67.93 (Volume in MBBL; Price in $/BBL) Q3-22 Q4-22 2H-22 Q1-23 Q2-23 Q3-23 Q4-23 FY-23 Ethane Swaps 386 386 773 - - - - - WTD Price $11.42 $11.42 $11.42 - - - - - Propane Swaps 294 294 589 - - - - - WTD Price $35.91 $35.91 $35.91 - - - - - Butane Swaps 92 92 184 - - - - - WTD Price $41.58 $41.58 $41.58 - - - - - Isobutane Swaps 28 28 55 - - - - - WTD Price $42.00 $42.00 $42.00 - - - - - Pentane Swaps 92 92 184 - - - - - WTD Price $60.65 $60.65 $60.65 - - - - - (Volume in MMBTU; Price in $/MMBTU) Q3-22 Q4-22 2H-22 Q1-23 Q2-23 Q3-23 Q4-23 FY-23 Henry Hub Swaps 920,000 920,000 1,840,000 - - - - - WTD Price $2.73 $2.73 $2.73 - - - - - Henry Hub Collars 7,360,000 7,360,000 14,720,000 6,300,000 6,370,000 6,440,000 6,440,000 25,550,000 WTD Floor Price $3.09 $3.09 $3.09 $4.14 $4.14 $4.14 $4.14 $4.14 WTD Ceiling Price $3.84 $3.84 $3.84 $8.43 $8.43 $8.43 $8.43 $8.43 Total Henry Hub Swaps/Collars 8,280,000 8,280,000 16,560,000 6,300,000 6,370,000 6,440,000 6,440,000 25,550,000 WTD Floor Price $3.05 $3.05 $3.05 $4.14 $4.14 $4.14 $4.14 $4.14 Waha Basis Swaps 7,314,000 7,314,000 14,628,000 6,300,000 6,370,000 6,440,000 6,440,000 25,550,000 WTD Price ($0.36) ($0.36) ($0.36) ($1.65) ($1.65) ($1.65) ($1.65) ($1.65) 1Hedges executed as of 9/6/2022 Active Hedge Program to Protect Free Cash Flow 14
1.95% 0.71% 0.37% 0.73% 0.78% FY-19A FY-20A FY-21A YTD-22A Zero routine flaring 15 <12.5 mtCO2e / MBOE <0.20% methane emissions1,2 18.08 17.54 12.50 2019 Baseline 2020 Performance Venting Reductions Flaring Reductions Pnuematics Reductions Combustion Reductions 2025 Target S c o p e 1 E m is s io n s m tC O 2 e / M B O E Defined Scope 1 Emissions Reduction Plan Systematic Plan to Achieve Emissions Reductions TrustWellTM Certification ▪ First Permian operator to receive TrustWellTM responsibly sourced certification ▪ Gold certification awarded for production from 73 horizontal wells representing ~31,500 BOEPD of gross operated production in the certification area ▪ Uniquely positioned among Permian Basin operators to benefit as premium markets are developed for certified responsibly sourced production Targets for 2025 12019 calendar year as baseline; 2As a percentage of natural gas production Percentage of Produced Natural Gas Flared / Vented Acquisitions Impact eu ti
1Data as of 12/31/2021; 2Data as of 7/31/2022 Corporate and Community Responsibility Local and Impactful Philanthropy >$820,000 Total amount donated since 2019 to improve our local communities1 Diversity and Inclusion Efforts1 EEO-1 Data Disclosed in Company’s 2021 ESG & Climate Risk Report 27% 26% 61% 60% Women in Workforce Minorities in Workforce Women and/or Minorities in Professional-or-higher Roles Female and Minority Directors2 16
Supplemental Non-GAAP Financial Measures Consolidated EBITDAX (Credit Agreement Calculation Unaudited) Consolidated EBITDAX is a non-GAAP financial measure defined in the Company’s Senior Secured Credit Facility as net income or loss (GAAP) plus adjustments for extraordinary gains (or losses), non-cash recurring gains (or losses), depletion, depreciation and amortization expense, interest expense, any provisions for (or benefit from) income or franchise taxes, exploration expenses and other non-cash charges. Consolidated EBITDAX is used by the Company’s management for various purposes, including as a measure of operating performance and compliance under the Company’s Senior Secured Credit Facility. Additional information on the calculation of Consolidate EBITDAX can be found in the Company’s Eighth Amendment to the Senior Secured Credit Facility as filed with the SEC on April 19, 2022. The following table presents a reconciliation of net income (loss) (GAAP) to Consolidated EBITDAX (non-GAAP) for the periods presented: 17 (in thousands, unaudited) 6/30/2022 3/31/2022 12/31/2021 9/30/2021 Net Income (loss) $262,546 ($86,781) $216,276 $136,832 Plus: Share-settled equity-based compensation, net 2,604 2,053 2,066 1,811 Depletion, depreciation and amortization 78,135 73,492 74,592 62,678 Mark-to-market on derivatives: (Gain) loss on derivatives, net 65,927 325,816 (15,372) 96,240 Settlements paid for matured derivatives, net (172,454) (125,370) (129,361) (92,726) Accretion expense 973 1,019 1,026 906 (Gain) loss on sale of oil and natural gas properties, net - - - (95,223) (Gain) loss on disposal of assets, net (38) 260 8,903 22 Interest expense 32,807 32,477 31,163 30,406 Loss on extinguished of debt, net 798 - - - Income tax (benefit) expense 7,092 (877) 3,052 2,677 Consolidated EBITDAX (non-GAAP) $278,390 $222,089 $192,345 $143,623 Three months ended,
Supplemental Non-GAAP Financial Measures PV-10 (Unaudited) PV-10 is a non-GAAP financial measure that is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. PV-10 is equal to the standardized measure of discounted future net cash flows at the applicable date, before deducting future income taxes, discounted at 10 percent. Management believes that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to the Company's estimated proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of the Company's proved oil, NGL and natural gas assets. Further, investors may utilize the measure as a basis for comparison of the relative size and value of proved reserves to other companies. The Company uses this measure when assessing the potential return on investment related to proved oil, NGL and natural gas assets. However, PV-10 is not a substitute for the standardized measure of discounted future net cash flows. The PV-10 measure and the standardized measure of discounted future net cash flows do not purport to present the fair value of the Company's oil, NGL and natural gas reserves of the property. 18 (in millions) December 31, 2021 Standardized measure of discounted future net cash flows $3,425 Less present value of future income taxes discounted at 10% (291) PV-10 (non-GAAP) $3,716
Supplemental Non-GAAP Financial Measures Net Debt (Unaudited) Net Debt, a non-GAAP financial measure, is calculated as the face value of long-term debt plus any outstanding letters of credit, less cash and cash equivalents. Management believes Net Debt is useful to management and investors in determining the Company’s leverage position since the Company has the ability, and may decide, to use a portion of its cash and cash equivalents to reduce debt. Net Debt as of June 30, 2022 was $1.159 billion. Net Debt to Consolidated EBITDAX (Unaudited) Net Debt to Consolidated EBITDAX, a non-GAAP financial measure, is calculated as Net Debt divided by Consolidated EBITDAX, for the previous four quarters, as defined in the Company's Senior Secured Credit Facility. Net Debt to Consolidated EBITDAX is used by the Company’s management for various purposes, including as a measure of operating performance, in presentations to its board of directors and as a basis for strategic planning and forecasting Free Cash Flow (Unaudited) Free Cash Flow is a non-GAAP financial measure that the Company defines as net cash provided by operating activities (GAAP) before changes in operating assets and liabilities, net, less incurred capital expenditures, excluding non-budgeted acquisition costs. Management believes Free Cash Flow is useful to management and investors in evaluating operating trends in its business that are affected by production, commodity prices, operating costs and other related factors. There are significant limitations to the use of Free Cash Flow as a measure of performance, including the lack of comparability due to the different methods of calculating Free Cash Flow reported by different companies. The Company is unable to provide a reconciliation of the forward-looking Free Cash Flow projection contained in this presentation to net cash provided by operating activities, the most directly comparable GAAP financial measure, because we cannot reliably predict certain of the necessary components of net cash provided by operating activities, such as changes in working capital, without unreasonable efforts. Such unavailable reconciling information may be significant. 19